Various types of downhole drilling tools including, but not limited to, rotary drill bits, reamers, core bits, and other downhole tools have been used to form wellbores in associated downhole formations. Examples of such rotary drill bits include, but are not limited to, fixed cutter drill bits, drag bits, polycrystalline diamond compact (PDC) drill bits, and matrix drill bits associated with forming oil and gas wells extending through one or more downhole formations. Fixed cutter drill bits such as PDC bits may include multiple blades that each include multiple cutting elements.
In typical drilling applications, a PDC bit may be used to drill through various levels or types of geological formations with longer bit life than non-PDC bits. Typical formations may generally have a relatively low compressive strength in the upper portions (e.g., lesser drilling depths) of the formation and a relatively high compressive strength in the lower portions (e.g., greater drilling depths) of the formation. Thus, it typically becomes increasingly more difficult to drill at increasingly greater depths.
A primary cutting element may experience increased wear as drilling depth increases. Thus, a drilling tool may include one or more back-up cutting elements configured to cut the geological formation when the primary cutting elements experience sufficient wear.
In conventional drill bits, the back-up cutting elements are placed on the same blade directly behind the primary cutting elements. This type of arrangement may require the under-exposure of the back-up cutting elements with respect to the primary cutting elements to be very small (e.g., approximately 0.01 in to 0.06 in) in order for the back-up cutting elements to act as depth of cut controllers. This conventional layout of back-up elements often results in the following: (a) if the primary cutting elements are not worn, the back-up cutting elements may never cut into the formation; (b) if the primary cutting elements wear slightly, only some of the back-up cutting elements may cut into the formation while other back-up cutting elements may never cut into the formation or may cut into the formation only slightly; and (c) if the primary cutting elements wear to a certain point, the back-up cutting elements may cut into the formation but the back-up cutting elements may never cut as effectively as the primary cutting elements. Each of these situations results in a shorter than expected bit life.